20240620IPC to Staff 1.pdf

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RECEIVED
Thursday June 20, 2024 8:OOAM
IDAHO PUBLIC
UTILITIES COMMISSION
LISA D. NORDSTROM
Lead Counsel
InordstrornC�idahopower.com
June 19, 2024
Monica Barrios-Sanchez, Secretary
Idaho Public Utilities Commission
11331 W. Chinden Boulevard
Building 8, Suite 201-A
Boise, Idaho 83714
Re: Case No. IPC-E-24-14
Idaho Power Company's Application for an Order Authorizing Inclusion in the
Bridger Balancing Account of all Non-Fuel Operations and Maintenance
Expenses Associated with Plant Operations.
Dear Ms. Barrios-Sanchez:
Attached for electronic filing, please find Idaho Power Company's Response to the
First Production Request of the Commission Staff in the above-entitled matter.
If you have any questions about the attached document, please do not hesitate to
contact me.
Sincerely,
O�ZL s
Lisa D. Nordstrom
LDN:sg
Attachment
1221 W. Idaho St(83702)
P.O. Box 70
Boise, ID 83707

LISA D. NORDSTROM (ISB No. 5733)
Idaho Power Company
1221 West Idaho Street (83702)
P.O. Box 70
Boise, Idaho 83707
Telephone: [phone]
Facsimile: [phone]
Inordstrom(a)_idahopower.com
Attorney for Idaho Power Company
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
IN THE MATTER OF IDAHO POWER )
COMPANY'S APPLICATION FOR AN ) CASE NO. IPC-E-24-14
ORDER AUTHORIZING INCLUSION IN )
THE BRIDGER BALANCING ACCOUNT ) IDAHO POWER COMPANY'S
OF ALL NON-FUEL OPERATIONS AND ) RESPONSE TO THE FIRST
MAINTENANCE EXPENSES ASSOCIATED ) PRODUCTION REQUEST OF
WITH PLANT OPERATIONS. ) THE COMMISSION STAFF TO
IDAHO POWER COMPANY
COMES NOW, Idaho Power Company ("Idaho Power" or "Company"), and in
response to the First Production Request of the Commission Staff ("Commission" or
"Staff") dated May 29, 2024, herewith submits the following information:
IDAHO POWER COMPANY'S RESPONSE TO THE FIRST PRODUCTION REQUEST OF THE
COMMISSION STAFF TO IDAHO POWER COMPANY - 1

REQUEST FOR PRODUCTION NO. 1: Please explain the Company's justification
supporting its decision to convert Bridger Units Nos. 1 and 2 to be fueled by natural gas
in 2024. In the explanation, please include, but not limit to, the following:
a. A list of all possible alternatives to converting the units to natural gas;
b. The rationale eliminating each of the possible alternatives by referencing and
including evidence such as any studies that were conducted, economic and risk
analysis comparing each alternative to natural gas conversion, reports produced
by the Company or from other sources, environmental regulatory documents
(FERC, EPA, etc.), and court orders, etc.; and
c. Agreement(s) with PacifiCorp that define the terms and conditions for the decision
to convert to natural gas.
RESPONSE TO REQUEST FOR PRODUCTION NO. 1: The economics of coal
plant ownership and operation have remained challenging because of the need for capital
investments for environmental retrofits. As a result, Idaho Power's Second Amended
2019 Integrated Resource Plan ("IRP"), acknowledged with Order No. 34959, identified a
preferred portfolio that included early Bridger unit exits in 2022, 2026, 2028, and 2030.
During development of the 2021 IRP, Idaho Power continued to analyze exiting from coal
units before the end of their depreciable lives. At the time, because Units 1 and 2 were
going to require Selective Catalytic Reduction investments by year-end 2021 and 2022
for continued coal operation, PacifiCorp, the operator of the plant with two-thirds
ownership, had modeled in their 2021 IRP various coal unit retirements and associated
gas conversions. Driven in part by ongoing cost pressures on existing coal-fired facilities
and dropping costs for new resource alternatives, PacifiCorp's 2021 IRP Preferred
IDAHO POWER COMPANY'S RESPONSE TO THE FIRST PRODUCTION REQUEST OF THE
COMMISSION STAFF TO IDAHO POWER COMPANY - 2

Portfolio included cessation of Bridger Unit 1 and Unit 2 coal-fired operations at the end
of 2023 and conversion to natural gas and operational in May of 2024 as a cost-effective
resource alternative. As such, for 2021 IRP modeling, Idaho Power also analyzed the
conversion of Bridger units to natural gas. The decision to convert the units to natural gas
was further supported when, on January 12, 2022, the Environmental Protection Agency
("EPA") proposed a rule that, if adopted, would disapprove the Wyoming State
Implementation Plan. The EPA ultimately rejected the Wyoming SIP, and the subsequent
consent decree made gas conversion the only path to compliance.
Idaho Power used AURORA's Long Term Capacity Expansion ("LTCE") modeling
capabilities, which produces optimized portfolios under various future conditions, to
generate resource portfolios. The logic of the LTCE model optimizes resource additions
and exits for each zone defined within the Western Electricity Coordinating Council.
Because Idaho Power's electrical system was modeled as a separate zone, the resource
portfolios produced by the LTCE were optimized for Idaho Power. The optimized
portfolios include the addition of supply-side and demand-side resources for the
Company's system, selecting from a broad range of resource types, with varied amounts
of nameplate generation additions, as well as exits from current coal-generation units and
converted natural gas units. Any costs associated with continued capital investments and
early exit or conversion were included in the analysis. If the units were converted to
natural gas, changes to the fuel costs and operating expenses were modeled to capture
the change in fuel.
Once the portfolios are created using the LTCE model, Idaho Power uses
AURORA as the primary tool for modeling resource operations and determining operating
IDAHO POWER COMPANY'S RESPONSE TO THE FIRST PRODUCTION REQUEST OF THE
COMMISSION STAFF TO IDAHO POWER COMPANY - 3

costs for a 20-year planning horizon, utilizing the resource buildouts from the LTCE model
as an input. AURORA applies economic principles and dispatch simulations to model the
relationships between generation, transmission, and demand to forecast market prices.
The operation of existing and future resources is based on forecasts of key fundamental
elements, such as demand, fuel prices, hydroelectric conditions, and operating
characteristics of new resources. Various mathematical algorithms are used in unit
dispatch, unit commitment, and regional pool-pricing logic. The algorithms simulate the
regional electrical system to determine how utility generation and transmission resources
operate to serve load. The result was the AURORA-produced optimized 2021 Preferred
Portfolio, acknowledged with Order No. 35603, that included the conversion of Units 1
and 2 from coal to natural gas by the summer of 2024, and the exit of coal-fired operations
in Units 3 and 4 by year-end 2025 and 2027, respectively. The conversion of Bridger Units
1 and 2 to natural gas was one of the least-cost, least-risk alternatives for meeting the
Company's resource needs.
a. See Chapter 5 of the 2021 IRP' for all future supply-side generation and storage
resources analyzed as part of the LTCE modeling performed in the IRP as potential
alternatives to the conversion to gas of Units 1 and 2. In order to determine the
best Bridger operating option specific to Idaho Power's system, the following
constraints were applied to Unit 1 and 2:
1. Unit 1 was allowed to exit year-end 2023 or convert to natural gas. If
converted to natural gas, the unit would operate through 2034, the
end of the planning period.
Case No. IPC-E-21-43, 2021 IRP, Chapter 5.
IDAHO POWER COMPANY'S RESPONSE TO THE FIRST PRODUCTION REQUEST OF THE
COMMISSION STAFF TO IDAHO POWER COMPANY -4

2. Unit 2 was allowed to exit between year-end 2023 and year-end 2026
or convert to natural gas as early as year-end 2023. If converted to
natural gas, the unit would operate through 2034, the end of the
planning period.
b. As described above, the logic of the LTCE model optimizes resource additions
and exits selecting from a broad range of resource types, with varied amounts of
nameplate generation additions, as well as exits from current coal-generation
units and converted natural gas units. Next, those portfolios are run through
AURORA to determine the operating costs for the 20-year planning horizon. The
different portfolios and their associated costs were compared as potential options
for a preferred portfolio. The resulting 2021 IRP Preferred Portfolio identifies the
least-cost, least-risk alternatives for meeting the Company's resource needs,
providing evidence that the alternatives considered were more costly, supporting
the Company's rationale for eliminating the possible alternatives and the
selection of Bridger Units 1 and 2 for conversion to natural gas.
c. There is no agreement that defined the terms and conditions for the decision to
convert to natural gas. However, Idaho Power and PacifiCorp are in the process
of updating and combining the current agreements under which the co-owners own
and operate Bridger.2 Because the agreements are over 50 years old and
encompass all aspects of Bridger plant ownership and operation including
2 The Agreement for the Ownership of the Jim Bridger Project between Idaho Power Company and
Pacific Power& Light Company, the Agreement for the Construction of the Jim Bridger Project between
Idaho Power Company and Pacific Power& Light Company, and the Agreement for the Operation of the
Jim Bridger Project between Idaho Power Company and Pacific Power& Light Company, all of which are
dated September 22, 1969, as amended by Amendments 1 through 9.
IDAHO POWER COMPANY'S RESPONSE TO THE FIRST PRODUCTION REQUEST OF THE
COMMISSION STAFF TO IDAHO POWER COMPANY - 5

payments of expenses, scheduling, identification of common facilities, water rights,
etc., the consolidation and modernizing process is lengthy and a new agreement
has not yet been executed. However, because gas operations have commenced,
the co-owners have finalized the Bridger Operation and Scheduling Terms
applicable to the units now that gas-fired operation is occurring. The terms, which
are included as Response to Staff's Request No. 1 — Attachment 1, will be a
component of the new ownership and operating agreement once complete. The
Company has also included as Response to Staff's Request No. 1 —Attachment 2
a copy of the email correspondence between the co-owners confirming use of the
Bridger operating agreement in the interim.
The response to this Request is sponsored by Jared Ellsworth, Transmission,
Distribution and Resource Planning Director, Idaho Power Company, and John
Carstensen, Joint Projects Leader, Idaho Power Company.
DATED at Boise, Idaho this 19th day of June 2024.
LISA D. NORDSTROM
Attorney for Idaho Power Company
IDAHO POWER COMPANY'S RESPONSE TO THE FIRST PRODUCTION REQUEST OF THE
COMMISSION STAFF TO IDAHO POWER COMPANY - 6

CERTIFICATE OF SERVICE
I HEREBY CERTIFY that on the 19th day of June 2024, 1 served a true and correct
copy of Idaho Power Company's Response to the First Production Request of the
Commission Staff to Idaho Power upon the following named parties by the method
indicated below, and addressed to the following:
Commission Staff Hand Delivered
Chris Burdin U.S. Mail
Deputy Attorney General Overnight Mail
Idaho Public Utilities Commission FAX
11331 W. Chinden Blvd., Bldg No. 8 FTP Site
Suite 201-A (83714) X Email Chris.Burdin(a-),puc.idaho.gov
PO Box 83720
Boise, ID 83720-0074
Stacy Gust
Regulatory Administrative Assistant
IDAHO POWER COMPANY'S RESPONSE TO THE FIRST PRODUCTION REQUEST OF THE
COMMISSION STAFF TO IDAHO POWER COMPANY - 7

BEFORE THE
IDAHO PUBLIC UTILITIES COMMISSION
CASE NO. IPC-E-24-14
IDAHO POWER COMPANY
REQUEST NO. 1
ATTACHMENT NO. 1

OPERATION AND SCHEDULING:
Each party shall have a right to schedule its percentage share of the Project coal and gas units
operating capability at any time as set forth below, provided that the schedule of a party shall not
require withdrawals from the coal stockpile in excess of the amount a party may withdraw under
Section N, or schedule the party's share of the gas unit beyond that party's available gas, other than by
agreement of the parties. The percentage share of the parties shall be Idaho Power 33-1/3%and
PacifiCorp 66-2/3%.
Gas Unit Scheduling
1) Either party can request a gas unit be brought online. The party requesting the unit to come online
must give notice by phone and email on or before the prescheduled day to the other party and pay
the start-up expense. The Operator will provide an estimated online time to both parties.
a) Either party may request a gas unit be brought online in the current day by giving
notice to the other party by phone. The Operator will provide an estimated online
time to both parties. If requested,the unit will be brought back online as soon as
possible.
2) If only one party is in the gas unit,that party is responsible for the entire unit minimum load. If both
parties are participating in the unit, both parties are responsible for their share of minimum load.
3) Each party participating in a unit shall have the option on the operating gas units to change their
own dispatch at any time.
4) A party may enter or exit an operating unit pursuant to the following:
a) A party may begin participation, during the operating day, in a unit they were
previously not dispatching(if the party meets the unit minimum off line time) by
giving a minimum of two hours' notice by phone to the other party and pay for its
share of startup costs as provided in the Operating Criteria document.
(i) Notwithstanding the above, a party may request to begin dispatching from an
operating unit that they were not previously dispatching with less than two
hours' notice upon the occurrence of a Contingency Event. In such a
Contingency Event, the party must have sufficient fuel to operate and provide as
much notice as practicable.
b) A party may exit a unit, during the operating day, (if the party meets the unit
minimum online time) by giving a minimum of four hours' notice by phone to the
other party.
c) A party may, but is not obligated to, provide more advance notice that it intends to
enter or exit a unit than the timelines described in (a) or(b). For example, a party
may provide notice on the preschedule day. Notice provided in advance of the

operating day will be provided by email to the other party and will indicate the date
and hour (Hour Ending PPT) of unit entry or exit.
5) Neither party shall schedule a ramp rate greater than such party's percentage share. However, a
party may receive an increased ramp rate depending on participation of the other party.
6) In the event a party elects not to schedule its share of the generation of a gas unit (either unit 1 or
2),that party is not eligible to receive operating reserves during the period it has elected not to
schedule any of its share of the gas units. The party operating its share can only capture its own
share of reserves.
7) The Operator shall promptly notify each party of any change in operating limits or operating
capability of the Project and, subject to paragraph 2 of this subsection, the parties shall thereupon
make any necessary changes to conform their respective generation schedules to their ownership
percentage share of such changed operating limits and capability. Idaho Power's share of the
Project's output shall not be reduced because of loading on the Project's 345/230 transformer bank
if PacifiCorp's scheduled transfers through said transformer bank exceed two-thirds of said
transformer bank's capacity in service."
8) The Operator shall notify by email each party by 10:00 am PPT of the preschedule day of the
forecast of the hourly available capacity of each of the units for seven days into the future.
9) The Operator shall, subject to unscheduled outages, operate the Project as scheduled by the parties
and shall hold deviations from schedule to a minimum and shall correct deviations from schedule as
soon as possible under the conditions.
10) Notice to the other party described in the sections above shall be made by either phone call or
email, as required above, to the following recipients:
To PacifiCorp/Operator:
Generation Desk
Phone: [phone]
Email: [e-mail]
ESM Resource Planning<[e-mail]>
To Idaho Power Company:
Generation Dispatch Desk
Phone: [phone]
Email: [e-mail]

BEFORE THE
IDAHO PUBLIC UTILITIES COMMISSION
CASE NO. IPC-E-24-14
IDAHO POWER COMPANY
REQUEST NO. 1
ATTACHMENT NO. 2

From: Finley, Elizabeth (PacifiCorp) <[e-mail]>
Sent: Wednesday, February 28, 2024 10:33 AM
To: Pugrud, Scott
Cc: Durrant, Marie (PacifiCorp); Richards, Brad (PacifiCorp); Bastian, Keith (PacifiCorp); Wood, Paul
(PacifiCorp) {Mkt Function}
Subject: [EXTERNAL] Jim Bridger Air Quality Permit and Compliance
KEEP IDAHO POWER SECURE! External emails may request information or contain malicious links or attachments.Verify the
sender before proceeding, and check for additional warning messages below.
Dear Scott,
Wyoming Air Quality Permit No. P0034936 authorizes emission limits for Units 1 and 2 after conversion to natural gas.
This email provides notice that PacifiCorp will operate those units within the parameters of the Wyoming permit and in
accordance with the Jim Bridger operating agreement. We are also outlining, at a high level, the concepts for the
forthcoming emission agreement between PacifiCorp and Idaho Power.
Emission limits under the Wyoming permit contain both rate and mass-based limits. The mass-based limits restrict each
unit's heat input to 21,900,000 MMBtu/year based on a 12-month rolling average of hourly heat input; a 1,314 tons per
year per unit annual NOx limit; and an 876 tons per year annual CO limit. Rate based limits of 0.12 lb. NOX/MMBtu and
0.08 CO Ib./MMBtu per unit and 720 NOX lb./hr. and 480 CO lb./hr. are based on 30-day rolling averages.
Rate-based limits only become effective on and after the date in which the performance test is conducted, while mass-
based limits will become effective immediately upon initial fuel burning. Based on plant projections initial fire in Unit 2
will begin late this week or early next week. PacifiCorp will use the following concepts for managing and allocating the
emission limits under the Wyoming permit.
• Mass-based limits will be allocated based on ownership share. PacifiCorp manages emissions rates as part of
good operating procedures and has determined that splitting the average NOx and CO rates between the parties
for each unit is not practical.
• Plant will track the 30-day rolling average limits of Ib/MMBtu and lb/hr. and make operational changes as
necessary to ensure compliance with the rate-based limit. Any derate under this scenario would apply to both
parties according to their Project share.
• An emissions agreement with IP will allocate NOX and CO tons and 21,900,000 MMBtu limits on a per unit per
party basis, parties will be allocated emission limits based on their ownership share of the unit.
o Monitors on each unit will track each party's tons-to-date per year.
o Emission data will be shared with parties weekly until that party gets within 15%of their limit at which
point it will be shared daily.
• Sections 4.2 and 10.6 of the operating agreement will govern PacifiCorp's actions and obligations relating to
operating within the emissions limits.
• As the plant operator, PacifiCorp retains the right to adjust plant operations as necessary to prevent exceedance
of a permit limit.
The goal is to have all emission data automated through Stack Vision and Pi such that both parties have real time
information regarding their own emission output and allowance. This process may take some time to perfect so in the
i

interim PacifiCorp will be providing weekly updates calculating Idaho Power's emission year to date of MMBtu, NOx tons
and CO tons.
Please let me know if you would like to discuss.
Thank you,
Liz
Elizabeth Elias Finley, P.G.
she/her/hers
Attorney
PacifiCorp/Rocky Mountain Power
[e-mail]
[phone]
4 PAC IFICORP
Rocky Mountain Power I Pacific Power
2